Gas Storage Capacity Research Articles

Facilitating clathrate hydrates with extremely rapid and high gas uptake for chemical-free carbon capture and methane storage

Clathrate hydrates are crystalline solid compounds comprising water and gas with remarkable potential for energy storage and carbon capture because of their large gas storage capacity and ability to selectively capture certain species upon crystallization. However, their use in real life has been hindered by low gas uptake kinetics, primarily limited by mass transfer. While extensive efforts have been made to overcome this limitation using chemical additives, their kinetic effects are insufficient, and environmental problems are caused. Here, the highest CO2 and CH4 gas uptake kinetics ever reported in clathrate hydrates were achieved without any chemical additives or mechanical mixing. The CO2 gas uptake rate and amount far exceeded previous records by 55.3% and 21.6%, respectively. Such excellent kinetics were accomplished using a fixed-bed reactor filled with surface-modified silica sand, which can be easily produced by simple treatment. Raman analysis and morphological studies demonstrated that its hydrophobic surface significantly affects interfacial interactions with water, greatly enhancing mass transfer. This new method is energy-efficient and environment-friendly, not requiring mechanical mixing or chemical injection at all. Mechanistic understandings of hydrate formation with hydrophobic surfaces would be applicable to hydrate-based carbon capture, methane storage, and natural gas hydrate production systems.

Dry Water as a Promoter for Gas Hydrate Formation: A Review.

Applications of clathrate hydrate require fast formation kinetics of it, which is the long-standing technological bottleneck due to mass transfer and heat transfer limitations. Although several methods, such as surfactants and mechanical stirring, have been employed to accelerate gas hydrate formation, the problems they bring are not negligible. Recently, a new water-in-air dispersion stabilized by hydrophobic nanosilica, dry water, has been used as an effective promoter for hydrate formation. In this review, we summarize the preparation procedure of dry water and factors affecting the physical properties of dry water dispersion. The effect of dry water dispersion on gas hydrate formation is discussed from the thermodynamic and kinetic points of view. Dry water dispersion shifts the gas hydrate phase boundary to milder conditions. Dry water increases the gas hydrate formation rate and improves gas storage capacity by enhancing water-guest gas contact. The performance comparison and synergy of dry water with other common hydrate promoters are also summarized. The self-preservation effect of dry water hydrate was investigated. Despite the prominent effect of dry water in promoting gas hydrate formation, its reusability problem still remains to be solved. We present and compare several methods to improve its reusability. Finally, we propose knowledge gaps in dry water hydrate research and future research directions.

Study on formation characteristics of carbon dioxide hydrate in modified carbon microtube system

The slow formation rate and low nucleation rate of carbon dioxide hydrate were common problems in current research. Many scholars focused on the promotion of gas hydrates by carbon nanotubes, whereas they ignored carbon microtubes, which were similar in structure and properties to carbon nanotubes and had more structural advantages. In this article, the effects of system temperature (1, 2, and 3 °C), pressure (3, 3.5, and 4 MPa), gas–liquid ratio (3:2, 4:1, and 5:1) and different types of carbon microtube concentration (0.01, 0.05, and 0.1 mg/mL) on the growth kinetics of carbon dioxide hydrate were investigated using orthogonal experiment method in a high-pressure reactor. The results revealed that compared to the pure carbon microtube system, amination, carboxylation, and hydroxylation carbon microtube systems improved the probability of carbon dioxide hydrate generation by 11–22%, with the shortest induction time of 0.23 hour. The highest gas storage capacity was 31.71 V/V under the carboxylated carbon microtube system. In the pure carbon, aminocarbon, carboxylated carbon and hydroxylated carbon microtube systems, the primary factors affecting the induction time were temperature, gas–liquid ratio, pressure and concentration. The gas–liquid ratio was the primary factor influencing the gas storage capacity of the carboxylated carbon microtubes; however, temperature was the primary factor affecting the gas storage capacity of the remaining three systems. Finally, we compared the effects of modified hydrophilic groups on the formation of carbon dioxide hydrate and made a conjecture.

Buoyant Flow of H2 Vs. CO2 in Storage Aquifers: Implications to Geological Screening

Summary Hydrogen will play an important role in the quest to decarbonize the world’s economy by substituting fossil fuels. In addition to the development of hydrogen generation technologies, the energy industry will need to increase hydrogen storage capacity to facilitate the development of a robust hydrogen economy. The required hydrogen storage capacity will be much larger than current hydrogen and natural gas storage capacities. There are several geological storage options for hydrogen that include depleted hydrocarbon fields and aquifers, where more research is needed until the feasibility of storing hydrogen at scale is proved. Here, we investigate the buoyant flow of H2 (as a working gas) vs. CO2 (as a cushion gas) separately in a representative storage aquifer. Buoyant flow can affect the maximum storage, capillary trapping, likelihood of leakage, and deliverability of aquifer-stored hydrogen. After building a 2D geological reservoir model initially filled with saline water, we ran numerical simulations to determine how hydrogen placed at the bottom of an aquifer might rise through the water column. The Leverett j-function is used to generate heterogeneous capillary entry pressure fields that correlate with porosity and permeability fields. Hydrogen viscosities were based on the Jossi et al. correlation, and the density was modeled using the Peng-Robinson equation of state. We then simulated several scenarios to assess flow during short- (annually) and long- (several years) term storage. For comparison purposes, we also ran CO2 storage simulations using the same geological model but with CO2-brine-rock properties collected from the literature. For a representative storage aquifer (323 K, 15.7 MPa, and mean permeability of 200 md), significant fingering occurred as the hydrogen rose through the saline water column. The hydrogen experienced more buoyant flow and created flow paths with increased fingering when compared with CO2. Individual hydrogen fingers are thinner than the CO2 fingers in the simulations, and the tips of hydrogen finger fronts propagated upward roughly twice as fast as the CO2 front for a typical set of heterogeneity indicators (Dykstra-Parson’s coefficient Vdp = 0.80, and dimensionless autocorrelation length λDx = 2). The implications of buoyant flow for hydrogen in saline aquifers include an increased threat of leakage, more residual trapping of hydrogen, and, therefore, the need to focus more on the heterogeneity and lateral correlation behavior of the repository. If hydrogen penetrates the caprock of an aquifer, it will leak faster than CO2 and generate more vertical flow pathways. We identify possible depositional environments for clastic aquifers that would offer suitable characteristics for storage.

Review on Cooperative Effect of Compound Additives on CO2 Hydrate Formation: Recent Advances and Future Directions

Hydrate-based CO2 sequestration is a novel technology to reduce CO2 emissions and mitigate global warming. The reduction of the induction time and increase of the formation rate and gas storage capacity are the key points for industrially storing CO2 hydrate. In this review, the research progress of various compound additives for promoting the formation of CO2 hydrate is reviewed. The promotion mechanisms of different additives and effects of different compound additives on the formation characteristics of CO2 hydrate are analyzed and summarized. Additionally, the promotion effects of different compound additives are compared and evaluated, challenges and constraints of the current compound additives discussed, and development trends and directions proposed.

Fluid phase behavior during multi-cycle injection and production of underground gas storage based on gas-condensate reservoirs with oil rim

Underground gas storage (UGS) plays an important role in energy supply and peak shaving of urban natural gas. Fluid phase behavior and mass transfer are complicated during multi-cycle injection and production of UGS especially based on gas-condensate reservoirs with oil rim, which will impact the fluid properties, gas-oil recovery factor and stability of UGS. This work innovatively develops an experimental approach to investigate the phase behavior during multi-cycle gas injection and production in a UGS based on gas-condensate reservoir with oil rim in Bohaiwan basin, China. The produced fluid composition, residual fluid properties and oil recovery factor are analyzed. Results indicated that the condensate oil recovery factor is only 24.12% and the oil rim influences condensate oil recovery factor during primary depletion. The oil recovery factors of individual cycles are 8.33%, 5.79%, 3.83%, 1.92% and 0.88%, respectively. The total condensate oil recovery is 20.75% after five cycles, indicating multi-cycle gas injection and production can effectively extract and evaporate oil phase especially in the first and second cycles. As the cycles increase, the composition difference between injected gas and oil rim becomes larger and the evaporation of oil rim by gas injection is weakened. The GOR of oil rim under the 24 MPa decrease from 190.5 to 162.5 m3/m3, indicating gas dissolving ability of oil rim decrease. The remaining oil saturation is 1.7% after five cycles, lower than the primary depletion (3.8%), indicating part of oil rim is also produced and the gas storage capacity is enhanced after multi-cycle injection and production. This work provides an approach to understand the phase behavior of UGS in condensate gas reservoirs with oil rim and is beneficial for the efficient operation of UGS.

Impacts of Different Operation Conditions and Geological Formation Characteristics on CO2 Sequestration in Citronelle Dome, Alabama

Major concerns of carbon dioxide (CO2) sequestration in subsurface formations are knowledge of the well injectivity and gas storage capacity of the formation, the CO2 pressure and saturation plume extensions during and after injection, and the risks associated with CO2 leakage and fault reactivation. Saline reservoirs are considered as one of the target formations for CO2 sequestration through structural, residual, dissolution, and mineral trapping mechanisms. The boundary condition of the saline reservoir dictates the pressure and saturation plume extension of the injected supercritical CO2 that could expand over large distances. This can lead to sources of risk, e.g., leakage and/or fault reactivation due to presence of wells, thief zones, and geological discontinuities. Therefore, there is a critical need to develop a model that describes how risk-related performance metrics (i.e., the CO2 saturation plume size, the pressure differential plume area, and the pressure differential at specific locations) vary as a function of the size of injection, time following injection, injection operations, and geologic environment. In this study, a systematic reservoir modeling studies of anthropogenic CO2 sequestration in Citronelle dome, Alabama, was performed where all relevant scenarios and conditions to address the questions of the saturation and pressure plume size in the area of review (AoR) and post-injection site care (PISC) are considered. The objective for this study was firstly to systematically simulate CO2 sequestration, i.e., saturation dynamics, and pressure behavior over a range of operational and geological conditions and to derive conclusions about the factors influencing saturation and pressure plume size, post-injection behavior, and the risk associated with them, by developing third-generation reduced order models (ROMs) for reservoir behavior. Finally, to assess the uncertainty associated with our studies, Latin Hypercube Sampling (LHS) together with an experimental design technique, i.e., Plackett–Burman design, was used. Application of Pareto charts and respond surfaces enabled us to determine the most important parameters impacting saturation and pressure plume sizes and to quantify the auto- and cross-correlation among different parameters in both history-matched and upscaled models.

Calcite–Fluid Interfacial Tension: H2 and CO2 Geological Storage in Carbonates

Underground hydrogen storage (UHS) and CO2 geological storage (CGS) are two outstanding techniques for meeting the universal energy demand and reducing anthropogenic greenhouse gases (GHGs). In this context, the calcite–fluid interfacial tension (γcalcite–fluid) is a critical parameter for gas s torage in carbonate formations as it affects the spreading and flow of fluids in porous media, gas injection/withdrawal rate, gas storage capacity, and containment safety. However, there is a scarcity of γcalcite–fluid data (e.g., γcalcite–gas and γcalcite–water for carbonate/gas/water systems) at geological conditions in the literature. In addition, there is no independent experimental method to measure γrock–fluid; thus, advancing and receding contact angles are often used to calculate it by a combination of Neumann’s equation of state and Young’s equation. We, therefore, theoretically calculated γcalcite–fluid as a function of the main geological parameters, including temperature, pressure, organic acid concentration, and salinity for calcite/H2/water and calcite/CO2/water systems. We recognized that γcalcite–gas decreased with pressure, salinity, and organic acid concentration but increased with temperature. Also, a slight increase in γcalcite–water with organic acid concentration and salinity was noticed at 15 MPa, 323.15 K, and 10 MPa, 323.15 K, respectively. However, γcalcite–water slightly decreased with temperature, assuming that it remained constant with pressure. Furthermore, the values of γcalcite–fluid for a H2/brine system were more than those for a CO2/brine system. This work thus provides a deep understanding of the wetting characteristics at calcite/H2/water and calcite/CO2/water interfaces and leads to a better investigation of H2/CO2 storage in carbonate formations.

Pore Structure and Adsorption Characteristics of Maceral Groups: Insights from Centrifugal Flotation Experiment of Coals.

Coal has various types of macerals, which have different pore structures and adsorption properties that change with coal's thermal metamorphism. In-depth study of the characteristics of different coal macerals, especially the pore structure and adsorption properties, can better predict the coal reservoir gas storage capacity and migration ability. In this study, the sub-samples enriched in a specific maceral group with different coal ranks and particle sizes were obtained by centrifugal flotation experiments. Then, experiments containing low-temperature N2 isotherm adsorption (LT-N2GA), low-temperature CO2 isotherm adsorption (LT-CO2GA), and methane isothermal adsorption were carried out on the sub-samples to quantitatively analyze the evolution characteristics of pore structure and adsorption properties of different maceral groups. The results showed the following: (1) The separation effect of the light maceral groups by centrifugal flotation experiments increased with the decrease of particle sizes, which were treated with the heavy liquid of low and medium densities, while that of the heavy maceral groups had the relatively best separation effect in the particle sizes of 0.1-0.125 mm, which were treated with the heavy liquid of high densities. (2) The vitrinite-enriched samples had more ultra-micropores (mainly within the diameter range of 0.4-0.65 nm), while the inertinite enriched samples had more mesopores and transition pores (mainly within the diameter range of 40-50 nm). (3) For the low-rank coal, inertinite had more potential methane adsorption capacity. However, for the medium- and high-rank coal, vitrinite had more potential methane adsorption capacity. (4) For the low-rank coal, the adsorption potential and adsorption space increased with the increase of the inertinite content, while the adsorption potential, adsorption space, and surface free energy for the medium- and high-rank coal increased with the increase of vitrinite content. It is expected that the results can deepen the understanding about the gas storage capacity and migration ability and be used in the prevention of gas outburst and the reduction of carbon emission.

CO2 Capture and Gas Storage Capacities Enhancement of HKUST-1 by Hybridization with Functionalized Graphene-like Materials.

The role of graphene related material (GRM) functionalization on the structural and adsorption properties of MOF-based hybrids was deepened by exploring the use of three GRMs obtained from the chemical demolition of a nanostructured carbon black. Oxidized graphene-like (GL-ox), hydrazine reduced graphene-like (GL), and amine-grafted graphene-like (GL-NH2) materials have been used for the preparation of Cu-HKUST-1 based hybrids. After a full structural characterization, the hybrid materials underwent many adsorption-desorption cycles to evaluate their capacities to capture CO2 and store CH4 at high pressure. All the MOF-based samples showed very high specific surface area (SSA) values and total pore volumes, but different pore size distributions attributed to the instauration of interactions between the MOF precursors and the specific functional groups on the GRM surface during MOF growth. All the samples showed a good affinity toward both gases (CO2 and CH4) and a comparable structural stability and integrity (possible aging was excluded). The trend of the maximum storage capacity values of the four MOF samples toward CO2 and CH4 was HKUST-1/GL-NH2 > HKUST-1 > HKUST-1/GL-ox > HKUST-1/GL. Overall, the measured CO2 and CH4 uptakes were in line with or higher than those already reported in the open literature for Cu-HKUST-1 based hybrids evaluated in similar conditions.

Insights into the CO2 Capture Characteristics within the Hierarchical Pores of Carbon Nanospheres Using Small-Angle Neutron Scattering.

Understanding adsorption processes at the molecular level has transformed the discovery of engineered materials for maximizing gas storage capacity and kinetics in adsorption-based carbon capture applications. In this work, we studied the molecular mechanism of gas (CO2, H2, methane, and ethane) adsorption inside an interconnected porous network of carbon. This was achieved by synthesizing novel macro-meso-microporous carbon (M3C) nanospheres with interconnected pore structures. The M3Cs showed a CO2 capture capacity of 5.3 mmol/g at atmospheric CO2 pressure, with excellent kinetics. This was due to fast CO2 adsorption within the interconnected hierarchical macro-meso-microporous M3C. In situ small-angle neutron scattering (SANS) under various CO2 pressures indicated that the macro- and mesopores of M3C enable fast diffusion of CO2 molecules inside the micropores, where adsorbed CO2 molecules densify into a liquid-like state. This strong densification of CO2 molecules causes fast CO2 diffusion in the macro- and mesopores of M3C, restarting the adsorption cycle for fresh CO2 molecules until all pores are completely filled. Notably, M3C also showed good capture capacities for hydrogen and various hydrocarbons, with excellent selectivity toward ethane over methane.

Role of molecular modelling in the development of metal-organic framework for gas adsorption applications.

The importance of density functional theory-based molecular modeling studies in offering design clues to improve the gas adsorption and storage capacity of existing MOF architectures is discussed here. The use of DFT-based investigation in conjunction with experimental synthesis is an imperative tool in designing new-generation MOFs with enhanced uptake capacity.

A Novel Performance Evaluation Method for Gas Reservoir-Type Underground Natural Gas Storage

The regulation of the seasonal energy supply for natural gas and the storage of fossil energy are important to society. To achieve it, storing a large amount of natural gas in porous underground media is one of the government’s choices. Due to the successful lesson learned from the oil and gas industry, natural gas storage in underground porous media has been regarded as the most potential long−term energy storage method. In this paper, we developed a new workflow to evaluate the performance of gas reservoir−type underground natural gas storage (UGS). The theoretical background of this workflow includes the correction of the average formation pressure (AFP) and gas deviation factor by error theory and the analytical mathematical model of UGS wells. The Laplace transform, line source function, and Stehfest numerical inversion methods were used to obtain pressure solutions for typical vertical and horizontal wells in UGS. The pressure superposition principle and weighting method of the gas injection−withdrawal rate were used to obtain the AFP. Through the correction of the AFP and gas deviation factor in the material balance equation, the parameters for inventory, effective inventory (the movable gas volume at standard condition), working gas volume (the movable gas volume is operated from the upper limit pressure to the lower limit pressure), and effective gas storage volume (the available gas storage volume at reservoir condition) were determined. Numerical data from the numerical simulator was used to verify the proposed model pressure solution. Actual data from China’s largest Hutubi UGS was used to illustrate the reliability of the proposed workflow in UGS performance evaluation. The results show that large−scale gas injection and withdrawal rates lead to composite heterogeneity in gas storage wells. The nine injection and production cycles’ pressure and effective inventory changes from Hutubi UGS can be divided into a period of rapid pressure rise and a period of slow pressure increase. The final AFP is 32.8 MPa. The final inventory of the Hutubi UGS is 100.1 × 108 m3, with a capacity filling rate (the ratio of effective inventory to designed gas storage capacity) of 93.6%. The effective inventory is 95.3 × 108 m3, and the inventory utilization ratio (the ratio of effective inventory to inventory) is 95.2%. The working gas volume is 40.3 × 108 m3. This study provides a new method for inventory evaluation of the gas reservoir−type UGS.

Investigations on Supercritical Methane Adsorption and Storage in the Lower Longmaxi Shale of Nanchuan Area, Southeast Sichuan Basin

A series of high-pressure methane adsorption measurements were performed at various temperatures on whole shale and kerogen samples collected from the Lower Longmaxi shale in the Nanchuan area, southeast Sichuan Basin, to investigate supercritical methane adsorption properties and evaluate in-place methane storage capacity as a function of burial depth. The results show that the supercritical Dubinin–Radushkevich (SDR) model fits the excess adsorption isotherms marginally better than the supercritical Langmuir model. However, the fitted adsorbed methane density of kerogens obtained from the SDR model may be greater than the liquid methane density at the atmospheric boiling point (0.423 g/cm3). The proposed multiple regression fitting carried out in this work illustrates that approximately 57.59% (34.51–85.45%) and 37.60% (10.74–59.52%) of the methane adsorption capacity at 333.15 K can be attributed to organic matter (OM) and clay minerals (CMs), respectively, for whole shales investigated. According to thermodynamic analyses, the significant contribution of OM to the methane adsorption capacity can be attributed to the stronger affinity between kerogens and methane molecules in contrast to that between CMs and whole shales. The methane storage capacity estimated as a function of burial depth showed that the adsorbed gas storage capacity declines with increasing burial depth between 2000 and 5000 m, while the free gas storage capacity shows the opposite trends. Gas accumulation pressure primarily exerts a significant effect on the free gas storage capacity rather than adsorbed gas storage capacity, and adsorbed gas storage capacity begins to exceed free gas storage capacity at shallow burial depths for normally pressured gas accumulations. Normally pressured shale gas accumulations at shallow burial depths, which are widely distributed in the residual syncline of the study area, should be given more attention due to their relatively low development costs and relatively high storage capacity for adsorbed gas.

An integrated model with stable numerical methods for fractured underground gas storage

Underground gas storage formed from the depleted oil/gas reservoir has excellent development potential for storing a large amount of natural gas. However, the reservoir in some regions is mostly a fractured structure. Its pore distribution and permeability theory are complex. An integrated model for the fractured underground gas storage (UGS) formed from the depleted oil/gas reservoir is proposed for the first time to respond to the absence of the numerical model. This integrated model couples the wellbore, reservoir and gas properties. We propose a gas flow direction factor and transient heat transfer models for the alternative flow directions in the wellbore. Natural gas property models are adopted to describe gas properties more accurately. We analyze the stability, efficiency and global mass conservation of the reservoir model. A new equation for source term is proposed to solve the reservoir model stably and efficiently. A pressure correction method is proposed to guarantee global mass conservation for long period operation of the UGS.Our simulation results indicate that the new equation for the source term ultimately ensures diagonal dominance and improves 20%–30% computational efficiency. The pressure correction method strictly guarantees global mass conservation. By simulating the entire cycle of gas injection, wellbore shutdown and gas production, we determine the maximum gas storage capacity of the UGS and analyze the variation law of pressure and temperature in the wellbore and reservoir.

LNG point supply of villages and towns in China: Challenges and countermeasures

Liquefied natural gas (LNG) point supply is one of the most flexible and convenient methods advocated by China for distributing energy to end-users such as towns and villages where it is difficult or uneconomical to construct gas pipelines. This study sorts out the advantages and challenges and designs the optimization model for LNG point supply in China based on a mixed-integer linear programming (MILP) model. In this model, the goal of optimization is to minimize economic and environmental costs in the construction and operation stages. By optimizing location-allocation, gas storage capacity, vaporization capacity, equipment selection, and pipeline distribution, the model meets the fluctuating seasonal demand for natural gas. This model design uses the actual construction and operation-related parameters of the vaporization station and pipeline, and applies the model to four different types of towns. Through sensitivity analysis, this study finds that the sensitivity of construction cost is relatively high.

Controlling and tuning CO2 hydrate nucleation and growth by metal-based ionic liquids

The complex kinetic process of CO2 hydrate formation limits its applications of CO2 capture and sequestration et al. In this work, the effects of metal-based ionic liquids with different cations and anions on CO2 hydrate nucleation and growth was studied. The results showed that CO2 hydrate nucleation was promoted by the anions of [NiCl3]-, [MnCl3]-, [FeCl4]-, [C8MIM]+ and [C16MIM]+ ions due to the enhancement of local hydrogen-bonding network to construct crystal nuclei. The induction time of CO2 hydrate nucleation was decreased by 75.0% in the [C16MIM]FeCl4 aqueous solution. However, CO2 hydrate nucleation was inhibited by [C2MIM]+ and [ZnCl3]- anion. The gas storage capacity of CO2 hydrate was increased by mass transfer channels around the metal complex anions which could accelerate the diffusion rate of H2O and CO2 molecules. The co-effect between [C16MIM]+ cations and [FeCl4]- anions on CO2 hydrate growth was the strongest, which increased gas storage capacity by 16.1%. Hence, CO2 hydrate formation can be controlled and tuned by changing cations and anions of metal-based ionic liquids.

Gas Storage Model of Residual Coal Adsorption in Abandoned Mine

Due to the insufficient accurate evaluation model of gas resources in abandoned mines, the development and utilization of abandoned mine gas resources in China are still in the preliminary exploration stage. To this end, in response to the problem of imprecise assessment of gas resource reserves in the adsorbed state of residual coal, the No. 3 coal seam in Jincheng mine was used as the research object, by analyzing the evolution of the ambient gas pressure and temperature of the residual coal in the abandoned mine, and simulating the pressure and temperature environment in which the residual coal is located, the gas adsorption experiment of the residual coal was carried out in this environment, and a gas storage model of the residual coal was constructed with the combination of the adsorption theory. The results show that pressure has a positive effect on gas adsorption by residual coal, while temperature has a negative effect on it. The adsorption potential gradually decreases with increasing pressure and increases with increasing temperature, while the adsorption space increases with increasing pressure and decreases with increasing temperature. The adsorption characteristic curves obtained by the two methods are temperature independent and polynomial in shape, and the fitted correlation coefficient of method 1 is generally higher than that of method 2. The adsorption characteristic curves of two methods are best fitted at [Formula: see text], so the value of [Formula: see text] is most appropriately taken as 2.5 when calculating the virtual saturation vapour pressure. The average relative errors between the predicted and measured values of method 1 and 2 were 2.98% and 7.13%, respectively. The prediction effect of method 1 was significantly better than that of method 2 and met the requirements of engineering applications; therefore, method 1 was used to establish a model for the adsorbed gas storage capacity of residual coal in abandoned mines.

Fabrication and Characterization of Nanoscale Metal-Organic Frameworks (MOFs) for Gas Storage and Separation

In recent years, Metal-Organic Frameworks (MOFs) have emerged as a promising class of materials for gas storage and separation applications due to their high surface area, tunable pore size, and chemical functionality. In this study, we report the successful fabrication and characterization of nanoscale MOFs for enhanced gas storage and separation performance. We synthesized a series of MOFs with varying metal nodes and organic linkers, and systematically investigated their structural, thermal, and chemical stability. Advanced characterization techniques, including X-ray diffraction, scanning electron microscopy, and gas adsorption isotherms, were employed to elucidate the structural and morphological features of the synthesized MOFs. The gas storage capacities of the MOFs were evaluated for hydrogen, methane, and carbon dioxide, revealing a significant enhancement in storage capacity compared to bulk MOFs. Furthermore, we investigated the gas separation performance of the MOFs for CO2/CH4 and CO2/N2 mixtures, demonstrating high selectivity and separation efficiency. The results of this study provide valuable insights into the design and fabrication of nanoscale MOFs for gas storage and separation applications, and pave the way for the development of next-generation materials for clean energy and environmental applications.

Effect of Water Saturation on Gas-Accessible Effective Pore Space in Gas Shales

Abstract The existence and content of water will certainly affect the effective pore space of shales and therefore is a key point for the evaluation of in-situ gas content and gas flow capacity of shale reservoirs. In order to reasonably evaluate the gas storage and flow capacities of water-bearing shale reservoirs, the effect of water on the effective pore space of shales needs to be understood. In this study, the Upper Permian Longtan shale in the southeastern Sichuan Basin, China, was selected as an example to conduct nuclear magnetic resonance cryoporometry (NMRC) measurements under different water saturation levels. The gas-accessible effective pore spaces in shales under different water saturation levels were quantified, and the effect of water saturation on gas-accessible effective pore space in shales was investigated. The results show that water plays an important role in the gas-accessible effective pore space of shales. When the Longtan shale increases from a dry state to a water saturation of 65%, 75%, and 90%, the gas-accessible effective pore volume decreases by 35%-60% (average 46.3%), 50%-70% (average 58.8%), and 65%-82% (average 75.8%), respectively. Water has an effect on the gas-accessible effective pore space regardless of pore size, and the effect is the strongest in the 4-100 nm range, which may be mainly due to the high content of clay minerals in the Longtan shale. Our studies are of important theoretical significance and application prospects for accurately evaluating the gas-accessible effective pore space of gas shales under actual geological conditions.